1. Field of the Invention
The present invention relates to evaluation of subsurface hydrocarbon reservoirs, and more particularly forming measures of the hydrocarbon content of tight gas reservoirs including shales, tight siliciclastic sands, and tight carbonates.
2. Description of the Related Art
In reservoir engineering, it has been important for reservoir evaluation to have as the starting point a measure of reserve or gas-in-place in a gas reservoir and volatile oil reservoir. However, for shale gas, so far as is known, no accurate method has been commonly accepted by the industry to estimate gas-in-place in a reservoir.
Existing methods have been based on above measures of water by laboratory testing of core samples obtained from cores extracted from subsurface formations by core sampling tools. There have been several deficiencies with existing methods. Obtaining cores with core sampling tools at depths of interest in a formation is expensive. Side-wall cores are thus generally only obtained at a few sporadic locations from a well. In addition once the cores have been obtained, their preservation to maintain fluid content for accurate results during ongoing laboratory evaluation and analysis of the reservoir has been notoriously difficult and full of uncertainty.
For unconventional shale gas reservoirs the presence of organic matter, in addition to the complex mineralogical composition, complicates the log based methods: the uncertainty in quantity and density of organic matter and other heavy minerals, such as pyrite, makes the density porosity inaccurate.
The large amount of hydrogen in organic matter and clay bound water leads to porosity estimation from neutron logs much higher than the real value. Resistivity logs fail to estimate water content in shale due to the presence of large amounts of clay and the associated surface conductivity. This excess conductivity must be accounted for. However, for clay rich shales, accounting for this excess conductivity can lead to large uncertainties in the computed water volumes.
For the core-measurement based methods, the basic porosity measurement in tight nanoporous shales is problematic. The extremely small dimensions of the pores make it difficult to clean and dry the pores. If the pores are not cleaned and dried, conventional porosity measurement methods do not provide accurate porosities. For example if the pores remain filled with water, it is not possible to expand helium into the pore space and quantitatively determine how much pore space there is in the sample.
Even when the porosity is accurately obtained, it remains difficult to estimate the hydrocarbon content based on porosity because a hydrocarbon storage model is required, which has not been reliably established. Shale contains three type of porosity, namely mineral-matrix porosity, organic-matter porosity, and fracture pores. It is not clear if hydrocarbon and/or water are present in all or only some of these pores in the reservoir. In addition, the adsorption on the pore surface can contribute a significant amount of reserve in a nanoporous system. However, the amount of adsorbed hydrocarbon at the reservoir condition may not be readily obtained from a laboratory measurement because all the pore surfaces, including those pores that only hold water in the reservoir, can contribute to the laboratory measurement. Furthermore, the presence of heavy hydrocarbons may result in capillary condensation in some shale gas reservoirs. In this condition, pore surface property and pore size distribution significantly impact the hydrocarbon in place. Therefore, laboratory measured porosity only has some guidance value in the estimation of hydrocarbon content for shale gas reservoir.